A plunger lift is an apparatus that is used to increase the productivity of oil and gas wells. In the early stages of a well's life, liquid loading is usually not a problem. When rates are high, the well liquids are carried out of the well tubing by the high velocity gas. As a well declines, a critical velocity is reached below which the heavier liquids do not make it to the surface and start to fall back to the bottom exerting back pressure on the formation, thus loading up the well. A plunger system is a method of unloading gas in high ratio oil wells without interrupting production. In operation, the plunger travels to the bottom of the well where the loading fluid is picked up by the plunger and is brought to the surface removing all liquids in the tubing. The plunger also keeps the tubing free of paraffin, salt or scale build-up. A plunger lift system works by cycling a well open and closed. During the open time a plunger interfaces between a liquid slug and gas. The gas below the plunger will push the plunger and liquid to the surface. This removal of the liquid from the tubing bore allows an additional volume of gas to flow from a producing well. A plunger lift requires sufficient gas presence within the well to be functional in driving the system. Oil wells making no gas are thus not plunger lift candidates.
As flow rate and pressures decline in a well, lifting efficiency can decline. Before long the well could begin to “load up”. This is a condition whereby the gas being produced by the formation can no longer carry the liquid being produced to the surface. There are two reasons this occurs. First, as liquid comes in contact with the wall of the production string of tubing, friction occurs. The velocity of the liquid is slowed, and some of the liquid adheres to the tubing wall, creating a film of liquid on the tubing wall.
This liquid may not reach the surface. Secondly, as the flow velocity continues to slow, the gas phase may no longer support liquid in either slug form or droplet form. This liquid, along with the liquid film on the sides of the tubing, may fall back to the bottom of the well. In a very aggravated situation, there could be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity very little liquid, if any, may be carried to the surface by the gas. A plunger lift will act to remove the accumulated liquid, thereby improving lifting efficiency.
A typical installation plunger lift system 100 can be seen in FIG. 1. Lubricator assembly 10 is one of the most important components of plunger system 100. Lubricator assembly 10 includes cap 1, integral top bumper spring 2, striking pad 3, and extracting rod 4A. Extracting rod 4A may or may not be employed depending on the plunger type. It is commonly used to open bypass valves and can be spring loaded. Contained within lubricator assembly 10 is plunger auto catching device 5 and plunger sensing device 6. Sensing device 6 sends a signal to surface controller 15 upon plunger 200A arrival at the well top. Plunger 200A can represent the plunger of the present invention or other prior art plungers. Sensing the plunger is used as a programming input to achieve the desired well production, flow times and wellhead operating pressures. Master valve 7 should be sized correctly for the tubing 9 and plunger 200A. An incorrectly sized master valve 7 will not allow plunger 200A to pass through. Master valve 7 should incorporate a full bore opening equal to the tubing 9 size. An oversized valve will allow gas to bypass the plunger causing it to stall in the valve. If the plunger is to be used in a well with relatively high formation pressures, care must be taken to balance tubing 9 size with the casing 8 size. The bottom of a well is typically equipped with a seating nipple/tubing stop 12. Spring standing valve/bottom hole bumper assembly 11 is located near the tubing bottom. The bumper spring is located above the standing valve and can be manufactured as an integral part of the standing valve or as a separate component of the plunger system. Fluid accumulating on top of plunger 200A may be carried to the well top by plunger 200A.
Surface control equipment usually consists of motor valve(s) 14, sensors 6, pressure recorders 16, etc., and an electronic controller 15 which opens and closes the well at the surface. Well flow ‘F’proceeds downstream when surface controller 15 opens well head flow valves. Controllers operate on time, or pressure, to open or close the surface valves based on operator-determined requirements for production. Modem electronic controllers incorporate features that are user friendly, easy to program, addressing the shortcomings of mechanical controllers and early electronic controllers. Additional features include: battery life extension through solar panel recharging, computer memory program retention in the event of battery failure and built-in lightning protection. For complex operating conditions, controllers can be purchased that have multiple valve capability to fully automate the production process.
FIGS. 2, 2A, 2B and 2C are side views of typical mandrel sections. Various existing sidewall geometries (known in prior art) can be used in conjunction with the present apparatus. In each of FIGS. 2-2C, an upper section of the plunger embodiment comprises a top collar shown with an internal standard American Petroleum Institute (API) fishing neck design A. If retrieval is required, a spring-loaded ball within a retriever and protruding outside its surface would thus fall within the API internal fishing neck at the top of the mandrel orifice to a point wherein the inside diameter of the orifice would increase to allow the ball to spring outward. This condition would allow retrieving of the plunger if, and when, necessary. Modification of each mandrel's lower section will be described below. Internal orifice 18 permits fluid to flow through each mandrel section shown as the plunger travels toward the well bottom bumper spring. A bypass valve (not shown) attaches via lower threads 19A and shuts off (closes) when the plunger reaches the bottom. The bypass feature optimizes plunger travel time in high liquid wells.
A. Plunger mandrel 20 is shown with solid ring 22 sidewall geometry. Solid sidewall rings 22 can be made of various materials such as steel, poly materials, Teflon®, stainless steel, etc. Inner cut grooves 30 allow sidewall debris to accumulate when a plunger is rising or falling.
B. Mandrel 80 is shown with shifting ring 81 sidewall geometry. Shifting rings 81 allow for continuous contact against the tubing to produce an effective seal with wiping action to ensure that all scale, salt or paraffin is removed from the tubing wall. Shifting rings 81 are individually separated at each upper surface and lower surface by air gap 82.
C. Plunger mandrel 60 has spring-loaded interlocking pads 61 in one or more sections. Interlocking pads 61 expand and contract to compensate for any irregularities in the tubing, thus creating a tight friction seal.
D. Plunger mandrel 70 incorporates a spiral-wound, flexible nylon brush 71 surface to create a seal and allow the plunger to travel despite the presence of sand, coal fines, tubing irregularities, etc.
E. Flexible plungers (not shown) are flexible for coiled tubing and directional holes, and can be used as well in straight standard tubing.
Recent practices toward slim-hole wells that utilize coiled tubing also lend themselves to plunger systems. Because of the small tubing diameters, a relatively small amount of liquid may cause a well to load-up, or a relatively small amount of paraffin may plug the tubing.
Plungers use the volume of gas stored in the casing and the formation during the shut-in time to push the liquid load and plunger to the surface when the motor valve opens the well to the sales line or to the atmosphere. To operate a plunger installation, only the pressure and gas volume in the tubing/casing annulus is usually considered as the source of energy for bringing the liquid load and plunger to the surface.
The major forces acting on the cross-sectional area of the bottom of the plunger are:                The pressure of the gas in the casing pushes up on the liquid load and the plunger.        The sales line operating pressure and atmospheric pressure push down on the plunger.        The weight of the liquid and the plunger weight push down on the plunger.        Once the plunger begins moving to the surface, friction between the tubing and the liquid load acts to oppose the plunger.        In addition, friction between the gas and tubing acts to slow the expansion of the gas.        
In an ideal plunger lift application, a plunger should travel quickly to a well bottom. When a plunger falls slowly to the bottom of a well, well efficiency is not maximized. Fluid build up can hamper the plunger's descent during the return trip to the bumper spring located at the well bottom. Thus, wells with a high fluid level tend to lower well production by delaying the cycle time of the plunger system, specifically delaying the plunger return trip to the well bottom. In other words, plunger fall time can affect well production. Use of bypass plungers with bypass valves permit the fluid to flow through the plunger during the return trip to the bumper spring located at the well bottom. In an open mode, the bypass feature allows a faster plunger travel time through fluid and down the hole in high liquid wells. Bypass plungers can have a variety of orifice openings or can have a variable orifice. The bypass valve provides a shut off feature when the plunger reaches the bottom.
In certain wells, or if an operator or controllers release a plunger prematurely, a plunger could fall towards the well bottom at a relatively high velocity. As the plunger collides with the well bottom, the well seating nipple/tubing stop 12, and/or the spring standing valve/bottom hole bumper assembly 11, the impact force is absorbed in part by the plunger, the spring standing valve/bottom hole bumper assembly 11, the well seating nipple/tubing stop 12 and the well bottom (FIG. 1). A higher velocity could lead to greater impact force and can result in damage to the plunger, and/or the spring standing valve/bottom hole bumper assembly. Bumper springs could collapse over time due to repeated stress caused by impact force. Also, plunger damage can occur resulting in more frequent plunger replacement. Because some wells do not have a bumper spring at the bottom, more of the impact could be absorbed by the plunger itself. A plunger could also rise at a high velocity from the well bottom to the well top. This can occur when liquid levels are low or when an operator allows the plunger to lift prior to proper liquid loading. A high velocity rise could cause damage to the well top apparatus and to the plunger itself. Damage to well apparatus and plunger lift equipment typically increases well maintenance cost. Prior art designs have utilized plungers with externally located springs to help absorb the energy generated by the plunger force hitting the well bottom.